Oil sands are a type of unconventional petroleum deposit. The sands contain naturally occurring mixtures of sand, clay, water, and a dense and extremely viscous form of petroleum technically referred to as “bitumen,” but may also be called heavy oil or tar. Many countries in the world have large deposits of oil sands, including the United States, Russia, and various countries in the Middle East. However, the world's largest deposits occur in Canada and Venezuela.
The crude bitumen contained in the Canadian oil sands is described as existing in the semi-solid or solid phase in natural deposits. Bitumen is a thick, sticky form of crude oil, so heavy and viscous (thick) that it will not flow unless heated or diluted with lighter hydrocarbons. At room temperature, it is much like cold molasses. Due to its high viscosity, these heavy oils are hard to mobilize, and they generally must be made to flow in order to produce and transport them.
Steam assisted gravity drainage (SAGD) is a commercial recovery process used for recovering heavy oil and bitumen that possess low to no mobility under native reservoir conditions. For SAGD, steam is circulated within horizontal injection and production wells that are spaced vertically 5 meters apart and placed near the base of the reservoir. Once fluid communication is established between the wells, the top well is operated as a dedicated injector well, and the bottom well is a producer well. With time, the steam melts the bitumen directly above the injector well and the resulting fluid is produced via gravity drainage to the base of the reservoir. Once steam reaches the top of the reservoir, the steam spreads horizontally within the reservoir, creating a steam chamber. As steam continues to be injected, the latent heat of vaporization of water drives the ability to melt and subsequently drain fluids for production. In the SAGD process, the produced fluid consists of an oil and water emulsion that can contain as much as 70% (w/w) water.
The rate at which fluid is produced by the reservoir is driven by both gravity drainage and the subcool, which is the temperature difference between the injector and producer wells. The added impact of subcool on production allows for the avoidance of the production of live steam, which can have significantly adverse effects on production facilities.
The temperature of produced fluids within a SAGD operation are lower than injected steam, but can still be in excess of 200° C. Although this is sufficient for maintaining the mobility of produced fluids, it is generally not sufficiently high enough to initiate chemical upgrading reactions within the reservoir. However, the controlled production of fluids within a SAGD operation does lend it to being combined with other processes that can produce sufficiently high temperatures to enable upgrading reactions.
FIG. 1 illustrates the rate at which water progresses through a developing steam chamber during normal SAGD operations. As shown, the velocity rate for water is between 0.2 and 0.5 m/day. As the steam chamber grows horizontally with time, this rate can be expected to decrease based on a decrease in the gravity drive for producing fluids. With this in mind, water may take anywhere from 50 to 125 days to vacate the reservoir. Chemical reactions require sufficient temperature and time of mixing to occur for the energy of activation of the reaction to be overcome. Although SAGD does not offer sufficient temperature as a standalone process, it is clear that the slow rate of the process can allow for sufficient mixing under proper conditions.
This ability to control the rate at which oil is drained from the reservoir allows for the opportunity to initiate chemical reactions that will allow for the hydrocarbon to be upgraded prior to producing the fluid from the reservoir. This will lead to a decrease or complete removal for the need of adding solvent at the surface for thinning the heavy oil and allowing transport to refineries. In addition, the oil will be more suitable for standard refinery configurations.
In situ upgrading has been attempted by using a solvent process known as VAPEX. In this approach, a solvent mobilizes the oil by decreasing its viscosity through a dissolution effect. During this process, asphaltenes, heteroatoms and heavy metals may precipitate, resulting in upgraded oil. Solvent to oil ratios are high, however, which makes this process economically unfeasible. In addition, as larger molecules precipitate, flocculation may occur, which may lead to the clogging of the producing well. Further, solvent usage contributes to negative ecological impact.
Alternative enhanced oil recovery mechanisms include Electro-Thermal Dynamic Stripping Process (ET-DSP) and In Situ Combustion (ISC). ET-DSP is a patented process that uses electricity to heat oil sands deposits to mobilize bitumen, allowing production using simple vertical wells. ISC uses oxygen to generate heat (fire) that diminishes oil viscosity; alongside carbon dioxide generated by heavy crude oil to displace the oil toward the production wells.
One ISC approach is called “THAI” for Toe to Heel Air Injection. This is an experimental method that combines a vertical air injection well with a horizontal production well. The process ignites oil in the reservoir and creates a vertical wall of fire moving from the “toe” of the horizontal well toward the “heel”, which burns the heavier oil components and upgrades some of the heavy bitumen into lighter oil right in the formation. Advocates of this method of extraction state that it uses less freshwater, produces 50% less greenhouse gases, and has a smaller footprint than other production techniques. Historically, however, there has been difficulty controlling the flame front and a propensity to set the producing wells on fire.
“CAPRI” is the variant of the THAI process that adds an annular sheath of solid catalyst surrounding the horizontal producer well. Thermally cracked oil produced by THAI passes through the layer of catalyst en-route to the horizontal producer well. Laboratory tests indicate that the combination of THAI and CAPRI can achieve significant upgrading. However, it is not clear that CAPRI can upgrade heavy oil to the point where it can be transported by pipeline without diluent. Thus, although a very promising technology, there is still room for improvement.
Thus, what is needed in the art are ecologically attractive methods of in situ upgrading of heavy oil that require less expenditure of energy, and yet still produce oil sufficiently light as to be transportable by pipeline.